1. Field of the Invention
The present invention relates to methods of producing hydrocarbons from a wellbore by utilizing optimized high-pressure water injection. More specifically, the present invention relates to enhancing recovery of hydrocarbons from ultra-tight oil resources, also often known as unconventional or shale resources.
2. Description of Background Art
Over the years, enormous strides in various oil extraction and oil recovery (also referred to as “oil production”) methods have been achieved, ranging from improved oil recovery (“IOR”) methods, incorporating technologies such as water injection into subterranean oil-bearing formations, to enhanced oil recovery (“EOR”) methods, incorporating technologies such as gas injection into subterranean oil-bearing formations.
The industry is also looking into recovering oil from geologic landscapes that formerly were economically challenged. For instance, ultra-tight permeability reservoirs often referred to as unconventional reservoirs or shale reservoirs. These reservoirs can contain hydrocarbons in the oil phase, gas phase, or both phases. The hydrocarbons in these reservoirs, however, may or may not actually be contained in true shales. In some cases, they are simply contained in very low permeability carbonates, siliciclastics, clays, or combinations thereof. A common attribute among this reservoir class is how they are typically developed. Many ultra-tight systems or shale reservoirs are economically developed using techniques such as horizontal wellbores and hydraulic fracturing to increase contact of the well with the formation The Bakken formation is one example of such an ultra-tight reservoir or subterranean hydrocarbon bearing formation.
Ultra-tight oil resources, such as the Bakken formation, have very low permeability compared to conventional resources. They are often stimulated using hydraulic fracturing techniques to enhance production and often employ ultra-long horizontal wellbores to commercialize the resource. However, even with these technological enhancements, these resources can be economically marginal and often only recover 5-15% of the original oil in place under primary depletion. Many of these resources can have variable wettability throughout the reservoir with much of the oil bearing rock having mixed- to oil-wet properties. This adverse wettability coupled with the ultra-tight pores and corresponding ultra-low permeability can make conventional water injection processes challenging. To date, there are no known successful water floods for very ultra-tight oil resources. In a sense, cyclic water injection has been carried out for many unconventional reservoirs to the degree that the hydraulic fracturing process utilizes water injected at high rate and pressure to mechanically break the subsurface formation. However, the chemical compositions, injection rates and durations, production strategy, and physical additives to the aqueous fracturing system are markedly different than what would be used in a cyclic water injection scheme aimed at enhancing oil recovery via traditional means.
In conventional oil fields, water injection to enhance recovery via more traditional mechanisms is one of the most commonly employed production enhancement techniques. Water injection provides voidage replacement and increases reservoir pressure, which assists in establishing the energy or driving force and creating the sweep needed for production of incremental oil that otherwise would not be produced. Over the past several decades, studies have been underway to optimize water injection in conventional reservoirs, examining additives such as alkali, surfactant, and polymer to improve sweep, reduce chemical adsorption, create favorable chemicals in situ, alter wettability, and establish more favorable interfacial tension and relative permeability characteristics. Much progress has been made in this technology area, but understanding the underlying mechanisms and optimizing the salinity, ions, pH, and chemical additives in an enhanced water injection scheme still remains a challenge.
To date, no successful waterflood or cyclic water injection methods for improving oil recovery have been successfully deployed in ultra-tight oil resources. This is due to the adverse wettability in the oil bearing pores (and even lack of understanding of where the oil resides, how it relates to mineralogy, and what mechanisms are at play which make these pores oil wet, in part due to the lack of techniques to investigate these fundamental physics at the pertinent scales (nanometer level) in ultra-tight systems). It is also due to the lack of injectivity in these ultra-tight pores where the median pore throat aperture can often be less than 50 nm. Technology is trending toward alternative water injection schemes that can overcome these challenges, but to date, no technology has been successfully developed. While traditional injection can often result in fracturing a formation after a long duration, this is often done unintentionally without care as to how rapidly it is done or for what duration or how effectively and efficiently it is done (i.e., how well fractures are generated and distributed along the length of the wellbore in the formation). These processes have all been traditionally done in vertical wells as well, which limit the need to effectively inject over a long distance (sometimes up to 2 miles) along the length of a horizontal wellbore. Methods of effectively distributing fluid along this length and inducing fractures along this length apart from the use of diverting agents has not been discussed.
As previously mentioned, hydraulic fracturing utilizes water and sand along with a suite of chemicals to mechanically fracture the subterranean formation. However, the injection rates, pressures, volumes, and durations as well as the chemical and physical constituents comprising the hydraulic fracturing fluids are targeted at breaking the subterranean formation, rather than penetrating into the formation, to act to replace void space, increase drive energy, alter wettability and relative permeability favorably and permanently. For example, in hydraulic fracturing processes, a high molecular weight polymer, typically polyacrylamide, is used as a “friction reducer” to reduce the effective drag on the hydraulic fracturing fluid as it is injected down the wellbore at high rates. These large molecular weight friction reducers, which can often have a molar mass of more than 10 million grams/mol, act to reduce the turbulence at the interface between the wellbore and the hydraulic fracturing fluid and thus reduce the overall friction losses. Friction reducers are used ubiquitously in hydraulic fracturing as they reduce the pumping horsepower required to fracture a reservoir, making it feasible to actually hydraulically fracture in some cases, while reducing the cost of the fracturing job. However, these large molecular weight polymers can actually have difficulty transporting through the ultra-tight pore throats in unconventional rock and plate out against the rock face, reducing the effective permeability of the matrix rock and impeding flow of the hydraulic fracturing fluid into the matrix. In addition, in many hydraulic fracturing jobs, gels are used, which further impede penetration into the matrix. Some lab tests have shown more than an order of magnitude reduction in the rate of penetration of hydraulic fracturing fluid into the matrix rock when including larger polymers in the hydraulic fracturing fluid.
Therefore, there is an industry-wide need for a method for recovering hydrocarbons from unconventional reservoirs, which maximize the recovery from these formerly challenged reservoirs.